*4.1. Description of the Case Study—Topology of the Planned VPP*

The planned virtual power plant is based on the fragment of the distribution network in Poland. The topology of the VPP on the distribution network scheme is presented in Figure 4. The VPP area consists of two parts of distribution networks supplied from two HV/MV main stations—110/20 kV *R-J* and *R-Z*. The supplied stations are connected to the 110 kV electrical power system (EPS). The 20 kV network, fed from *R-J* station, is an overhead-cable network. The 20 kV network, fed from *R-Z* station, is mainly an urban cable network. Both networks work with earth fault current compensation.

Inside the mentioned distribution networks, there are several distributed energy sources and energy storage systems. Planned VPP consists of hydro power plant, photovoltaic power plant, biogas generation units and combined heat and power unit based on combined installation using boiler and steam turbine integrated with generator and heating system in the industry. An integral element of planed VPP is the prosumers mainly using photovoltaic systems. Detailed information about the DERs identified in the area of the VPP is presented in Table 2. The detailed information about ESSs localized in the VPP area is presented in Table 3. In the first part of the distribution network supplied from the station *R-J*, a crucial element of the planned VPP is the hydro power plant denoted as *HPP-L*

with generating power about 0.94 MW and battery energy storage system *ESS-L* connected to the same node of MV network as hydro power plant with installed power 0.5 MW. In the second part of the distribution network supplied from the station *R-Z*, a photovoltaic power plant *PV-C* with generating power of 0.1 MW and an associated energy storage system can be noted.

**Figure 4.** Topology of the planned virtual power plant (VPP).



**Table 3.** Energy storage system (ESS) integrated with the VPP.


*4.2. Identification of the Impact of the Active Power Changes Generated by the DER and ESS on the Load Reduction in the Distribution Line, as well as the Voltage Changes in the Nodes of the Grid Covered by the VPP*

In order to illustrate the technical aspects related to the integration of DER and ESS with electric power systems and also their impact on resources available to the VPP control, the issue of identifying the maximum power capacity of ESS is presented with regards to network requirements concerning voltage level and rapid voltage changes. The network requirements were described in Section 2. This paper aims to reveal the maximum capacity of the ESS that is planned to be attached to the

same node as analyzed HPP. The investigated approach does not consider the valuable aspects of the interaction of ESSs with different RES at respective locations or analyze the advantages and disadvantages of using one ESS vs multiple small ESSs. However, these mentioned issues have been investigated in point of the economic aspects and are presented in associated paper [36]. The presented investigations are performed using Matlab modeling integrated with a database of real measurements of power flows. Referring to the VPP topology presented in Figure 4, the appropriate model was created and simulations were carried out in order to identify:


Firstly, in order to associate the model with the real operating conditions of the distribution network associated with the VPP a steady state initial condition of power flows was prepared. Power flows were prepared based on the available set of annual real measurements of load demands and power generated by DER. Loads consist of the two main HV/MV transformers and all busbars of the power stations *R-J* and *R-Z*. One day of measurements, representing summer maximum peak demand, was selected. The day was selected based on the analysis of the database of the Polish power system load, which is shared by the Polish Transmission System Operator [70]. The presented investigations concern the day 14.07.2017 at 1 PM. A simplified scheme of the electrical connection of the VPP, with denoted instantaneous power flow measurements at the time of the identified summer peak demand value, is presented in Figure 5.

**Figure 5.** A simplified scheme of the electrical connection of the VPP, with denoted instantaneous power flow measurements at the time of the identified summer peak demand value.

Secondly, a Matlab Simulink model of the VPP topology, consisting of the described 20 kV networks, hydro power plant, battery energy storage and photovoltaic power plant was created and validated. The model is the dynamic model and captures several aspects related to dynamic representations of DERs and BES. In the case of HPP simulation, a standard electro-hydraulic speed controller model was used. The mechanical time constant and the time of waterfall was calculated based on the real parameters and equals 2 s and 3 s, respectively. The static excitation system was chosen according to the IEEE type ST1A excitation system mode in Matlab. The dynamics of the system are determined by the parameters of the voltage regulator and equalizer. Both elements are represented by an inertial element with the following parameters:

• regulator: *Gr*(*s*) <sup>=</sup> *Ka* <sup>1</sup>+*Tas*, with assumed parameters: *Gr*(*s*) <sup>=</sup> <sup>210</sup> <sup>1</sup>+0.100*<sup>s</sup>*

 $\bullet \quad \text{equalizer: } G\_f(s) = \frac{K\_f s}{1 + T\_f s},$  with assumed parameters:  $G\_f(s) = \frac{0.001s}{1 + s}$ .

In the case of the battery energy storage system, a functional modeling assumption was made that BES works like a controllable source of active and reactive power. The phenomena and processes occurring in the cells as well as in the control and commutation system of the inverter are not taken into consideration in the applied model. Applied limits are connected to restrictions on the discharge and charge current, the battery charge level and the power change speed. An ideal *P,Q* inverter regulation system, controlled by voltage magnitude and phase, was applied. Simulation of the BES operation in the grid was realized in accordance to the selected scenario, for example, determining the time intervals for energy return and battery charging. In addition, it is necessary to determine the power of exchange with the grid (discharge and charge current) and to also control the battery charge level. For this purpose, the *P,Q* inverter model was supplemented with a battery charge control system. The condition for the simulations assumed the use of the BES that was planned in the VPP project, with nominal parameters of 0.5 MW of maximal power *P*max and a 0.5 MWh of maximum capacity. Additionally, a limitation for the speed of power change in the simulations was implemented to ± 10%*P*max/s. The numerical values given in the figures refer to BES with a 0.5 MW power and a 0.5 MWh useful capacity. The PV power plant is also modeled using the *P,Q* inverter model. However, in the performed simulations of short time intervals, fixed values of active and reactive power were used on the basis of real measurements collected for the investigated PV-C. In the applied model of PV-C, the issue of generation changes due to radiation and temperature changes are neglected. Initial condition for the simulation was supported by the real measurement data which represents selected summer peak demand.

Simulation time of 24 min (1440 s) was selected, which allowed all the assumed events in the simulation scenario, while at the same time maintaining the real dynamics of energy sources and storage systems during switching operations, to be performed. Time of the simulation results from the time interval of control and regulations systems. In the simulation model the issue of water turbine response, mechanical constant, limitation of the speed of power changes in the control of BES have been implemented. The particular time interval associated with the planned switching operations, carried out in the generation units and energy storage system, are defined in the scenario of the simulated events. The simulations use the algorithm for solving differential Equations known as ode24tb, which works with a variable integration step. The maximum integration step was 10−<sup>4</sup> s, while the actual step was selected automatically. The accuracy of the timestamp is not worse than 10−<sup>4</sup> s.

With regards to the scheme of the electrical power network in the area of the planned VPP (Figure 4), the presented simulations are focused on the active power changes and voltage changes of particular VPP elements, including:


The scenario of events consists of several switching operations carried out in the generation units and energy storage system:


Active power changes in the distribution line *L-62,* associated with main statin *R-*J and hydropower plant *HPP-*L with battery storage system *ESS-L* during series of switching operations of *HPP-L*, *PV-C* and *ESS-L* are presented in Figure 6. It can be seen that the gradual increase of active power generated by the hydro power plant *HPP-L* from zero to the assumed setup of 940 kW generating power decreases the load demand in line L-62 which connects *HPP-L* with the main station *R-*J. The achieving by *HPP-L* a preset of 940 kW takes 1000 s but it can be concluded that the power flow of the observed line *L-62* changes the direction from load demand to generation after approximately 150 s when the generation of the *HPP-L* obtains a level of 500 kW. Switching on the battery energy storage *ESS-L* additionally increases the level of transmitted generation power by the observed line. Naturally, the observed process has a positive impact on decreasing the load demand of the transformer in the main station *R-J*. Figure 7 presents active power changes in the high voltage/medium voltage (HV/MV) transformer in the main station *R-J* during the switching operation series of *HPP-L*, *PV-C* and *ESS-L*.

With regards to the network requirements for the voltage changes caused by the integration of the DERs with the electrical power systems presented in Section 2, the assessment of the influence of the simulated series of the switching operations of *HPP-L*, *PV-C* and *ESS-L* on the voltage changes in the connection point of the DER, as well as on the secondary side of the HV/MV transformer, is presented. When observing Figures 8 and 9, it may be indicated that inserting the active power from *HPP-*L into the associated line *L-62* causes a slow voltage increase at the 20 kV busbar of the hydro power plant on the level of 1%. At the same time, the voltage on the 20 kV busbars at the main station *R-J* changes by less than 0.1%. When the *ESS-L* generates about 500 kW, there is an increase in voltage at 20 kV busbar of the connection point of *HPP-L* and *ESS-L* approximately on the level of 0.6% and a slight change in voltage. A sudden switching off of the *HPP-L* and *ESS-L* causes a rapid voltage change at the connection point of these energy sources on the level of 1.6% and simultaneously a rapid voltage change of less than 0.1% at the 20 kV busbar of the main station *R-J*.

**Figure 6.** Active power changes *P* in the distribution line *L-62* associated with main station *R-J*. Changes of generated power of hydropower plant *HPP-L*. Changes of generated power of battery storage system *ESS-L*. Analysis carried out during a series of switching operations of *HPP-L*, *PV-C* and *ESS-L*.

**Figure 7.** Active power changes *P* in the high voltage/medium voltage (HV/MV) transformer in the main station *R-J* during the series of switching operations of *HPP-L*, *PV-*C and *ESS-L*.

**Figure 8.** Voltage changes *U* in the connection point of the hydropower plant *HPP-*L and battery energy storage system *ESS-L* during the series of switching operations of *HPP-L*, *PV-C* and *ESS-L*.

**Figure 9.** Voltage changes *U* at the secondary side of the HV/MV transformer in the main station *R-J* during the series of switching operations of *HPP-L*, *PV-*C and *ESS-L*.

When observing voltage changes at the secondary side of the HV/MV transformer in the main station *R-Z* presented in Figure 10, it may be concluded that the generation of active power in analyzed network connected to the main station *R-J* is slightly noticeable at the busbar of station *R-Z* which is associated with station *R-J* by high voltage line. Additionally, switching on the photovoltaic installation *PV-C* with 100 kW of active power causes a slight change in voltage at the 20 kV busbar of the main station *R-Z* that is not noticeable in the station *R-J*. However, it should be emphasized that the observed changes are small and at the level of one-hundredth of a percent of the 20 kV nominal value. Noticed voltage changes can be compared with the quoted requirement of voltage changes on the level of three percentage and permissible value of voltage level not more than 10% of nominal value [60].

**Figure 10.** Voltage changes *U* at the secondary side of the HV/MV transformer in the main station *R-Z* during the series of switching operations of *HPP-L*, *PV-C* and *ESS-L*.

The simulations aimed to identify the direct impact of the active power changes generated by the HPP and BES on the load reduction in the distribution line, as well as on the voltage changes in the node of the connection and the substation. Therefore, standard methods of voltage regulations, including the on-load-tap-changer, were not used in the simulations. In reality, the tap-changer control is implemented in the main substations 110/20 kV, denoted as *R-J* and *R-Z*. However, the classical regulation strategy for the HV/MV transformer often uses a step of regulation on the level of 1.09–1.10%. In presented simulations indicated changes of voltage level in the main substations caused by BES or *PV-C* were less than the classical step of on-load-tap-changer regulation.
